This invention relates to the field of well logging of earth wellbores and, more particularly, to methods for measuring flow velocity in an earth formation with nuclear magnetic resonance techniques and for using the measured flow velocity to determine various other important well logging parameters.
Well logging provides various parameters that may be used to determine the xe2x80x9cqualityxe2x80x9d of a formation from a given wellbore. These parameters include such factors as: formation pressure, resistivity, porosity, bound fluid volume and hydraulic permeability. These parameters, which are used to evaluate the quality of a given formation, may provide, for example, the amount of hydrocarbons present within the formation, as well as an indication as to the difficulty in extracting those hydrocarbons from the formation. Hydraulic permeabilityxe2x80x94how easily the hydrocarbons will flow through the pores of the formationxe2x80x94is therefore, an important factor in determining whether a specific well site is commercially viable.
There are various known techniques for determining hydraulic permeability, as well as other well logging parameters. For example, it is known how to derive permeability from nuclear magnetic resonance (NMR) measurements. NMR measurements, in general, are accomplished by causing the magnetic moments of nuclei in a formation to precess about an axis. The axis about which the nuclei precess may be established by applying a strong, polarizing, static magnetic field (BO) to the formation, such as through the use of permanent magnets (i.e., polarization). This field causes the proton spins to align in a direction parallel to the applied field (this step, which is sometimes referred to as longitudinal magnetization, results in the nuclei being xe2x80x9cpolarizedxe2x80x9d). Polarization does not occur immediately, but instead grows in accordance with a time constant Tl, as described more fully below, and may take as long as several seconds to occur (even up to about eight seconds or longer). After sufficient time, a thermal equilibrium polarization parallel to BO has been established.
Next, a series of radio frequency (RF) pulses are produced so that an oscillating magnetic field Bl is applied. The first RF pulse (referred to as the 90xc2x0 pulse) must be strong enough to rotate the magnetization from BO substantially into the transverse plane (i.e., transverse magnetization). The rotation angle is given by:
xcex1=B1xcex3tpxe2x80x83xe2x80x83(1) 
and is adjusted, by methods known to those skilled in the art, to be 90xc2x0 (where tp is the pulse length and xcex3 is the gyromagnetic ratioxe2x80x94a nuclear constant). Additional RF pulses (referred to as 180xc2x0 pulses where xcex1=180xc2x0) are applied to create a series of spin echoes. The additional RF pulses typically are applied in accordance with a pulse squence, such as the error-correcting CPMG (Carr-Purcell-Meiboom-Gill) NMR pulse sequence, to facilitate rapid and accurate data collection. The frequency of the RF pulses is chosen to excite specific nuclear spins in the particular region of the sample that is being investigated. The rotation angles of the RF pulses are adjusted to be 90xc2x0 and 180xc2x0 in the center of this region.
Two time constants are associated with the relaxation process of the longitudinal and transverse magnetization. These time constants characterize the rate of return to thermal equilibrium of the magnetization components following the application of each 90xc2x0 pulse. The spin-lattice relaxation time (T1) is the time constant for the longitudinal magnetization component to return to its thermal equilibrium (after the application of the static magnetic field). The spinxe2x80x94spin relaxation time (T2) is the time constant for the transverse magnetization to return to its thermal equilibrium value which is zero. Typically, T2 distributions are measured using a pulse sequence such as the CMPG pulse sequence described above. In addition, BO is typically inhomogeneous and the transverse magnetization decays with the shorter time constant T2*, where:                               1                      T            2            *                          =                              1                          T              2                                +                      1                          T              xe2x80x2                                                          (        2        )            
In the absence of motion and diffusion, the decay with characteristic time Txe2x80x2 is due to BO inhomogeneities alone. In this case, it is completely reversible and can be recovered in successive echoes. The amplitudes of successive echoes decay with T2. Upon obtaining the T2 distributions, other formation characteristics, such as permeability, may be determined.
A potential problem with the T2 distributions may occur if the echo decays faster than predicted, for example, if motion of the measuring probe occurs during measurements. Under these conditions, the resultant data may be degraded. Thus, for example, displacement of the measurement device due to fast logging speed, rough wellbore conditions or vibrations of the drill string during logging-while-drilling (LWD) may prevent accurate measurements from being obtained.
Moreover, it also is known that T2 distributions do not always accurately represent pore size. For example, G. R. Coates et al., xe2x80x9cA New Characterization of Bulk-Volume Irreducible Using Magnetic Resonance,xe2x80x9d SPWLA 38th Annual Logging Symposium, Jun. 15-18, 1997, describes the measurement of bound fluid volume by relating each relaxation time to a specific fraction of capillary bound water. This method assumes that each pore size has an inherent irreducible water saturation (i.e., regardless of pore size, some water will always be trapped within the pores). In addition, the presence of hydrocarbons in water wet rocks changes the correlation between the T2 distribution and pore size.
Hydraulic permeability of the formation is one of the most important characteristics of a hydrocarbon reservoir and one of the most difficult quantitative measurements to obtain. Often permeability is derived from T2 distributions, created from NMR experiments, which represent pore size distributions. Finally, permeability is related to the T2 data. This way to determine permeability has several drawbacks and is therefore sometimes inapplicable.
Typically T2 distributions are measured using the error-correcting CPMG pulse sequence. In order to provide meaningful results, the length of the recorded echo train must be at least T2max. During this time period, as well as during the preceding prepolarization period, the measurement is sensitive to displacements of the measuring device. Further, in some cases, the T2 distributions do not represent pore size distributions, e.g., hydrocarbons in water wet rocks change the correlation between T2 distribution and pore size distribution. Finally, the correlation between pore size distribution and permeability of the formation is achieved using several phenomenological formulae that are based on large measured data sets, displaying relatively weak correlation. In carbonates, these formulae breakdown because of the formations"" complex pore shapes.
A more direct way to measure permeability is by measurements of induced flow rates using a packer or probe tool. Still, this measurement requires extensive modeling of the formation response which includes the geometry of the reservoir and of the tool, the mud cake, and the invasion zone. The effort required for modeling however, could be significantly reduced if flow velocity could be obtained. It would be advantageous to obtain flow velocity, which could be used to determine various parameters required for modeling so that the number of variables required for modeling is reduced.
For at least the foregoing reasons, it is an object of the present invention to provide apparatus and methods for determining flow velocity utilizing NMR techniques.
It is a still further object of the present invention to provide methods for determining permeability utilizing NMR measurements of flow velocity.
It is an even further object of the present invention to provide methods for determining the extent of drilling damage to the formation, formation pressure, mud filtration rate and changes in the invaded zone during sampling utilizing NMR measurements of flow velocity.
These and other objects of the invention are accomplished in accordance with the principles of the invention by providing methods and apparatus for determining flow velocity utilizing nuclear magnetic resonance (NMR) techniques and for providing measurements of other wellbore parameters based on the flow velocity measurements. The preferred embodiments include methods and apparatus in which flow velocity is determined without knowledge of T2 or the pressure distribution. The flow velocity measurements are made using NMR techniques in which the shape of the resonance region is varied depending on whether radial or vertical sensitivity is desired. In an embodiment that requires knowledge of T2, the decay of the echo amplitude is measured. If both radial and vertical sensitivity are desired, multiple NMR devices may be provided in a single wellbore tool where each NMR device is designed to measure a specific orientation.
In other preferred embodiments of the present invention, NMR determination of frequency displacement, rather than signal decay, is utilized to determine flow velocity. An advantage of these techniques also is that no reference measurements need be taken because the detection of signal decay is not employed. This can be achieved by analyzing the echo shape instead of the echo amplitude or by standard NMR one-dimensional frequency selective or two-dimensional methods. In still other preferred embodiments, an encoding pulse is substituted for the traditional 90xc2x0 pulse, and adiabatic pulses are substituted for the traditional 180xc2x0 pulses. These techniques are advantageous if the BO gradient is small, e.g., in the case of a BO saddle point, because only an inhomogeneous field B1 is required, rather than a BO gradient.
The methods and apparatus of the present invention for obtaining flow velocity using NMR techniques also are applicable to determining various wellbore parameters during wellbore drilling operations. For example, by inducing fluid to flow within the formation such as by withdrawing fluid from the formation into the NMR tool or into the wellbore, the NMR determination of flow velocity may be used in conjunction with a differential pressure measurement to provide a direct, small-scale measurement of permeability due to the fact that the NMR data provides an extremely localized measurement of fluid velocity. Alternatively, the NMR techniques of the present invention may be used to obtain an assessment of the drilling damage to the formation.
In addition, the NMR techniques of the present invention may be used to determine formation pressure by establishing conditions in the wellbore (for example, by using a packer module) such that no filtration of wellbore fluid occurs across the mudcake and simultaneously measuring the pressure at the interface between the mudcake and the formation. Another important parameter that may be determined using the NMR techniques of the present invention is mud filtration rate (sometimes referred to as invasion). This parameter may be particularly important because it provides a direct measure of the quality of the mud system being employed and may provide an advance indication of potential problems. Also, the NMR techniques of the present invention may be used to monitor changes in the invaded zone during sampling operations. Under such conditions, it is often important to monitor the migration of fine mud particles (or xe2x80x9cfinesxe2x80x9d) that may give rise to plugging of the formation where the sampling is being conducted. Moreover, while the determination of various operational parameters is described herein, persons skilled in the art will appreciate that various other parameters may be obtained utilizing the NMR techniques of the present invention.